1. Field of Invention
The present invention relates generally to the field of hydrocarbon production, more particularly to methods for obtaining a wellbore schematic, and using same to monitor wellbore service operations.
2. Related Art
Due primarily to expense issues, the hydrocarbon production industry has come to accept taking surface measurements and making inferences of the downhole status. However, interpretation of real-time wellbore pressure data requires knowledge of the wellbore schematic, in particular the wellbore's variation of depth below the earth surface (“true vertical depth”, or TVD) versus its depth along the wellbore axis (measured depth, MD or just “depth”). In circumstances where the wellbore schematic is not known in advance by the interpreter, the wellbore schematic may be obtained directly by including a inclinometer in a downhole tool, but this option is not always available or economical.
In making wellbore pressure interpretations, the pressure read by a downhole meter inside a tubular such as coiled tubing will be the pressure in the tubing at the surface (the “circulating pressure”) less friction effects due to flow and plus the hydrostatic pressure, which is proportional to the TVD. For a uniform fluid, the hydrostatic pressure is given by the density of the fluid in ppg times 0.052 psi/ppg/ft. For a typical brine, this works out to approximately 0.5 psi/ft (11.3 kPa/m) of TVD. For a non-uniform fluid, integration along the length of the tubing is required. At zero flow, the TVD is thus given by subtracting the circulating pressure from the bottom-hole pressure and dividing by the constant of proportionality. It is uncommon (and sometimes inefficient) to run coiled tubing into the bottom of the wellbore without pumping fluid, however. When pumping fluid downhole through tubing, the bottom-hole pressure at the terminus of the tubing will be decreased by the friction of the fluid in the tubing. For laminar flow of Newtonian fluids, friction pressure equals a constant multiplied by the flow rate. For turbulent flow of Newtonian fluids, friction pressure equals a constant multiplied by the flow rate squared. In each case the constant of proportionality depends upon the tubing internal geometry as well as the local friction factor between the fluid and the inner tubing surface. For typical fluids pumped through coiled-tubing, there may be a different formula for computing friction loss for the component of the fluid flowing through the spooled coil at the surface, versus that fluid flowing in the tubing hanging in the wellbore. For non-Newtonian fluids, yet more complicated relationships exist between the circulating friction loss and the flow-rate.
In wellbore cleanout procedures and other procedures where liquids are pumped into the wellbore via tubing and out through the annulus, if hydrostatic head pressure may be removed, one has an accurate estimate of the wellbore pressure at the bottom of (entrance to) the annulus. However, the only way to remove the hydrostatic component from downhole data is to have a copy of the wellbore schematic in advance of the job. This schematic could have been obtained while drilling the well via measurement-while-drilling data, or after drilling by lowering a wireline inclinometer tool such as a gyroscope. However, no tool that is currently used for stimulating reservoirs is known to have an internal inclinometry platform, nor is there known any previously existing method to determine TVD strictly from pressure data and flow rate information.
In wellbore cleanout operations, various fill materials are carried by a fluid injected down the wellbore, typically through coiled tubing or other tubulars, and flowed out through the annulus. The cleanout fluid carrying solid particles along the annulus is a suspension whose density correlates with the concentration of solid particles. For an effective cleanout the suspended particles must be transported all the way out of the well. The hydrodynamic pressure in the annulus is directly proportional to the suspension density.
It would be an advance in the art if methods could be devised that provide information about the relationship between TVD vs. MD, in other words the wellbore schematic, while flowing fluids into the wellbore. It would further be an advance in the art to use the obtained wellbore schematic to monitor and/or control wellbore operations, such as wellbore cleanout procedures, via information about the annulus.